Production of fluids from oil and gas reservoirs containing high levels of hydrogen sulfide (H2S) requires the separation of the H2S from both the produced oil and the produced natural gas and the safe disposal thereof. There are at least two widely practiced methods of processing natural gas with high H2S. In one known method, the entire H2S-containing natural gas stream (also referred to herein as sour gas) is dehydrated, compressed, and reinjected at high pressure in an underground formation. In another known method, the gas is sweetened in an amine unit using amine scrubbing, followed by dehydration and optionally fractionation to extract propane and butane prior to being sold as sales gas (containing mostly methane, ethane and some nitrogen). The H2S and CO2 removed from gas processing in the amine unit (collectively referred to as acid gas) are sent to a Sulfur Recovery Unit (SRU) where the H2S is converted to elemental sulfur via the well-known Claus reaction. An additional tail-gas treating unit may provide further treatment to ensure that SOX emissions are minimal.
To process the oil phase from the produced fluids, after separation from the natural gas phase and water in one or more three-phase separators, the oil stream is often flashed in one or more stages to remove light components (including H2S). Lastly, the oil is sent to a stabilizer column which further strips more light ends and H2S from the oil to meet a final vapor-pressure specification on the product oil. All of the gases from the flash steps in the oil processing along with the stabilizer overhead gases may be combined, recompressed, and mixed with the sour gas. Some integrated facilities include parallel trains for oil production integrated with sour gas processing and sour gas injection.
The known integrated facilities described above have several limitations. For one thing, the inlet gas-to-oil ratio (GOR) and % H2S in oil and gas production fields tend to increase over time as the reservoir ages and with prolonged sour gas injection. Facilities are designed with finite limits on H2S treating, sulfur conversion capacity and sour gas injection capacity. Reservoir pressure also drops over time as the reservoir ages. To ensure that feed gas is supplied to the facilities at adequate and consistent pressure, one known method is to install field compression near the wellheads to boost the inlet pressure. This pressure boost compressor also has a limited capacity. Furthermore, there are times when market prices for the treated natural gas are low, and thus oil production is the main revenue source for such integrated facilities. Oil production then becomes constrained by a facility's ability to dispose of the sour gas, either by processing or by injection. Reaching capacity in one or more parts of the plant often results in bottlenecks in which other parts of the plant are underutilized and thus capacity is wasted.
It would be desirable to find ways to debottleneck integrated facilities that treat produced fluids containing high levels of hydrogen sulfide that include oil production, sour gas processing and sour gas injection.